135
Exploration, Recovery, and Transportation
In microemulsion flooding, the slug must be designed for specific reservoir conditions of temperature, resident water salinity, and crude oil type. If the temperature is very high, a fluid-handling problem
may result in the field because of the increased vapor pressure of the hydrocarbon in microemulsion.
In analyzing the applicability of microemulsion-polymer flooding to a given reservoir, the need
for a thorough understanding of the reservoir and fluid characteristics cannot be overemphasized.
As mentioned, such characteristics as the nature of the oil and water content, relative permeability,
mobility ratios, formation fractures, and variations in permeability, porosity, formation continuity,
and rock mineralogy can have a dramatic effect on the success or failure of the process.
Conventional waterflooding can often be improved by the addition of polymers (polymer
flooding) to injection water to improve the mobility ratio between the injected and in-place fluids.
The polymer solution affects the relative flow rates of oil and water and sweeps a larger fraction of
the reservoir than water alone, thus contacting more of the oil and moving it to production wells.
Polymers currently in use are produced both synthetically (polyacrylamides) and biologically (polysaccharides). The polymers may also be cross-linked in situ to form highly viscous fluids that will
divert the subsequently injected water into different reservoir strata.
Polymer flooding has its greatest utility in heterogeneous reservoirs and those that contain moderately viscous oils. Oil reservoirs with adverse water flood mobility ratios have a potential for
increased oil recovery through better horizontal sweep efficiency. Heterogeneous reservoirs may
respond favorably as a result of improved vertical sweep efficiency. Because the microscopic displacement efficiency is not affected, the increase in recovery over water flood will likely be modest
and limited to the extent that sweep efficiency is improved, but the incremental cost is also moderate. Currently, polymer flooding is being used in a significant number of commercial field projects.
The process may be used to recover oils of higher viscosity than those for which a surfactant flood
might be considered.
Polymer solutions must be stable for a prolonged period at reservoir conditions. Mechanical,
chemical, thermal, and microbial effects can degrade polymers. However, degradation can be minimized or even prevented by using specific equipment or methods (Table 6.3).
Stability problems may occur as a result of oxygen contamination of the polymer solutions.
Such contamination can lower the screen factor of polyacrylamide solutions by as much as 30%.
In field operations, the loss of mobility reduction due to oxygen may be more serious since control
of the reservoir fluid composition can be difficult. Sodium hydrosulfite in low concentrations is
an effective oxygen collector for polyacrylamide solutions. However, sodium hydrosulfite tends to
catalyze polymer deterioration when free oxygen and decomposed polymers are present. Therefore,
the proper use of sodium hydrosulfite is imperative to avoid severe polymer degradation. In addition, caution is necessary to prevent oxygen from reentering the system once sodium hydrosulfite
has been added to the makeup water.
Surfactant flooding is a multiple-slug process involving the addition of surface-active chemicals
to water. These chemicals reduce the capillary forces that trap the oil in the pores of the rock. The
surfactant slug displaces the majority of the oil from the reservoir volume contacted, forming a
flowing oil–water bank that is propagated ahead of the surfactant slug. The principal factors that
influence the surfactant slug design are interfacial properties, slug mobility in relation to the mobility of the oil–water bank, the persistence of acceptable slug properties and slug integrity in the
reservoir, and cost.
A slug of water containing polymer in solution follows the surfactant slug. The polymer solution
is injected to preserve the integrity of the more costly surfactant slug and to improve the sweep
efficiency. Both these goals are achieved by adjusting the polymer solution viscosity in relation to
the viscosity of the surfactant slug to obtain a favorable mobility ratio. The polymer solution is then
followed by injection of drive water, which continues until the project is completed.
Each reservoir has unique fluid and rock properties, and specific chemical systems must be
designed for each individual application. The chemicals used, their concentrations in the slugs, and
Exploration, Recovery, and Transportation
In microemulsion flooding, the slug must be designed for specific reservoir conditions of temperature, resident water salinity, and crude oil type. If the temperature is very high, a fluid-handling problem
may result in the field because of the increased vapor pressure of the hydrocarbon in microemulsion.
In analyzing the applicability of microemulsion-polymer flooding to a given reservoir, the need
for a thorough understanding of the reservoir and fluid characteristics cannot be overemphasized.
As mentioned, such characteristics as the nature of the oil and water content, relative permeability,
mobility ratios, formation fractures, and variations in permeability, porosity, formation continuity,
and rock mineralogy can have a dramatic effect on the success or failure of the process.
Conventional waterflooding can often be improved by the addition of polymers (polymer
flooding) to injection water to improve the mobility ratio between the injected and in-place fluids.
The polymer solution affects the relative flow rates of oil and water and sweeps a larger fraction of
the reservoir than water alone, thus contacting more of the oil and moving it to production wells.
Polymers currently in use are produced both synthetically (polyacrylamides) and biologically (polysaccharides). The polymers may also be cross-linked in situ to form highly viscous fluids that will
divert the subsequently injected water into different reservoir strata.
Polymer flooding has its greatest utility in heterogeneous reservoirs and those that contain moderately viscous oils. Oil reservoirs with adverse water flood mobility ratios have a potential for
increased oil recovery through better horizontal sweep efficiency. Heterogeneous reservoirs may
respond favorably as a result of improved vertical sweep efficiency. Because the microscopic displacement efficiency is not affected, the increase in recovery over water flood will likely be modest
and limited to the extent that sweep efficiency is improved, but the incremental cost is also moderate. Currently, polymer flooding is being used in a significant number of commercial field projects.
The process may be used to recover oils of higher viscosity than those for which a surfactant flood
might be considered.
Polymer solutions must be stable for a prolonged period at reservoir conditions. Mechanical,
chemical, thermal, and microbial effects can degrade polymers. However, degradation can be minimized or even prevented by using specific equipment or methods (Table 6.3).
Stability problems may occur as a result of oxygen contamination of the polymer solutions.
Such contamination can lower the screen factor of polyacrylamide solutions by as much as 30%.
In field operations, the loss of mobility reduction due to oxygen may be more serious since control
of the reservoir fluid composition can be difficult. Sodium hydrosulfite in low concentrations is
an effective oxygen collector for polyacrylamide solutions. However, sodium hydrosulfite tends to
catalyze polymer deterioration when free oxygen and decomposed polymers are present. Therefore,
the proper use of sodium hydrosulfite is imperative to avoid severe polymer degradation. In addition, caution is necessary to prevent oxygen from reentering the system once sodium hydrosulfite
has been added to the makeup water.
Surfactant flooding is a multiple-slug process involving the addition of surface-active chemicals
to water. These chemicals reduce the capillary forces that trap the oil in the pores of the rock. The
surfactant slug displaces the majority of the oil from the reservoir volume contacted, forming a
flowing oil–water bank that is propagated ahead of the surfactant slug. The principal factors that
influence the surfactant slug design are interfacial properties, slug mobility in relation to the mobility of the oil–water bank, the persistence of acceptable slug properties and slug integrity in the
reservoir, and cost.
A slug of water containing polymer in solution follows the surfactant slug. The polymer solution
is injected to preserve the integrity of the more costly surfactant slug and to improve the sweep
efficiency. Both these goals are achieved by adjusting the polymer solution viscosity in relation to
the viscosity of the surfactant slug to obtain a favorable mobility ratio. The polymer solution is then
followed by injection of drive water, which continues until the project is completed.
Each reservoir has unique fluid and rock properties, and specific chemical systems must be
designed for each individual application. The chemicals used, their concentrations in the slugs, and